With reference to FIG. 1, production of hydrocarbons (oil and/or gas) from subsea oil/gas wells typically involves positioning several items of production equipment 18, 20, e.g., Christmas trees, manifolds, pipelines, flowline skids, pipeline end terminations (PLETs), etc. on the sea floor 16. Flowlines or jumpers 22 are normally coupled to these various items of equipment 18, 20 so as to allow the produced hydrocarbons to flow between and among such production equipment with the ultimate objective being to get the produced hydrocarbon fluids to a desired end-point, e.g., a surface vessel or structure, an on-shore storage facility or pipeline, etc. Jumpers may be used to connect the individual wellheads to a central manifold. In other cases, relatively flexible lines may be employed to connect some of the subsea equipment items to one another. The generic term “flowline” will be used throughout this application to refer to any type of line through which hydrocarbon-containing fluids can be produced from a subsea well.
One challenge facing offshore oil and gas operations involves insuring the flowlines and fluid flow paths within subsea equipment remain open so that production fluid may continue to be produced. The produced hydrocarbon fluids will typically comprise a mixture of crude oil, water, light hydrocarbon gases (such as methane), and other gases such as hydrogen sulfide and carbon dioxide. In some instances, solid materials or debris, such as sand, small rocks, pipe scale or rust, etc., may be mixed with the production fluid as product travels through the flowline. The same challenge applies to other subsea flowlines and fluid flow paths used for activities related to the production of hydrocarbons. These other flowlines and flow paths could be used to, for example, service the subsea production system (service lines), for injecting water, gas or other mixture of fluids into subsea wells (injection lines) or for transporting other fluids, or hydraulic control lines operating equipment that come in direct contact with production fluids and causing a potential contamination of control fluids (control lines) should seal barriers degrade.
Problems encountered in the production of hydrocarbon fluids from subsea wells are often multi-faceted where blockage may form in a subsea flowline or in a piece of subsea equipment from a variety of causes from hydrate formation to coagulation or precipitation of byproducts from different fluids coming in contact with one another. In some cases the blockage can completely block passageways (flowlines or control/service lines) while in other cases there is only partially blockage to the flowline/equipment which thereby degrades performance or throughput. However, as used herein, the term “blockage” should be understood to complete or partial blockage of a passageway. For example, solid materials entrained in the produced fluids may be deposited during temporary production shut-downs, and the entrained debris may settle so as to form all or part of a blockage in a flowline or item of production equipment. As another example chemical reactions between two (normally separate) fluids may result in an unwanted precipitate or byproduct that could create a blockage.
In general, hydrates may form under appropriate high pressure and low temperature conditions. As a general rule of thumb, hydrates may form at a pressure greater than about 0.47 MPa (about 1000 psi) and a temperature of less than about 21° C. (about 70° F.), although these numbers may vary depending upon the particular application and the composition of the production fluid. Subsea oil and gas wells that are located at water depths greater than a few hundred feet or located in cold weather environments, are typically exposed to water that is at a temperature of less than about 21° C. (about 70° F.) and, in some situations, the surrounding water may only be a few degrees above freezing. Although the produced hydrocarbon fluid is relatively hot as it initially leaves the wellhead, as it flows through the subsea production equipment and flowlines, the surrounding water will cool the produced fluid. More specifically, the produced hydrocarbon fluids will cool rapidly when the flow is interrupted for any length of time, such as by a temporary production shut-down. If the production fluid is allowed to cool to below the hydrate formation temperature for the production fluid and the pressure is above the hydrate formation pressure for the production fluid, hydrates may form in the produced fluid which, in turn, may ultimately form a blockage which may block the production fluid flow paths through the production flowlines and/or production equipment. Of course, the precise conditions for the formation of hydrates, e.g., the right combination of low temperature and high pressure is a function of, among other things, the gas-to-water composition in the production fluid which may vary from well to well. When such a blockage forms in a flowline or in a piece of production equipment, either a hydrate blockage or a debris blockage or a combination of both, it must be removed so that normal production activities may be resumed.
When a hydrate blockage does form in the flowline 22 or the production equipment 18, 20, the only recourse is to do one or more of (1) reducing the pressure on one (or both) sides of the hydrate blockage restriction; (2) warm the surrounding equipment; and/or (3) introduce chemicals to change phase properties to melt the hydrate blockage so as to re-open the flowline or equipment. These hydrate remediation tasks are often time consuming and, depending on where the hydrate blockage forms, it may be more problematic to remove. The remediation process also requires a high degree of pressure integrity, i.e., insuring the absence of spurious or extraneous small leak path sources associated with intervention hardware and conduits. Otherwise diagnosing and monitoring desired changes and rates in pressure, temperature, chemical treatment rates, and avoidance of water or other contaminating sources ingress may hamper or thwart attempts to remove the blockage. With reference to FIG. 1, hydrate remediation activities often involve use of a surface vessel 12 that is located on the surface 14 of the water, an ROV (Remotely Operated Vehicle) 30 that is operatively coupled to the vessel 12 via a schematically depicted line 24 to enable an operator on the vessel 12 to control the ROV 30. In this example, a hydrate remediation skid 32 is coupled to the ROV 30. In some cases, the hydrate remediation skid 32 may include various sensors (e.g., pressure, temperature, etc.), pumps, valves, and the like so as to allow the performance of one or more the hydrate remediation activities described above. In some case, the hydrate remediation skid 32 may also contain its own supply of chemicals, e.g., methanol, to be injected into the flowline/equipment. The ROV 30 also includes a simplistically depicted robotic arm 31 and a schematically depicted ROV hot-stab 40 that is coupled to the ROV 30 via a tether or umbilical 44. In some applications, the hot-stab 40 may also include a schematically depicted manually actuated isolation valve 43 that may be mechanically actuated by use of the robotic arm 31. See, for example, U.S. Pat. No. 6,009,950 and US Patent Publication 20130334448. In general, during various hydrate remediation activities, the end 42 of the hot-stab 40 may be inserted into any of a plurality of simplistically depicted access points 23 in the flowlines 22 and/or the equipment 18, 20 so that certain activities may be performed. For example, chemicals may be injected into the flowlines 22 and/or the equipment 18, 20 via the hot-stab 40 using the equipment on the hydrate remediation skid 32. As another example, production fluid and or sublimated components of the hydrate blockage may be withdrawn from the flowlines 22 and/or the equipment 18, 20 via the hot-stab 40 using the equipment on the hydrate remediation skid 32.
In any event, when production is lost due to the formation of a hydrate blockage, the operator's revenue stream is curtailed and the only option may be to bleed off pressure downstream of the hydrate blockage to a pressure that is less than the hydrate formation pressure. In some cases, this means a large portion of the equipment infrastructure must be shut in and hydrocarbons vented so that the hydrate blockage can slowly sublimate from the depressurize side of the blockage. Eventually the blockage melts a sufficient amount such that it frees itself from the sides of the bore in the flowline/equipment. At that point the trapped higher pressure behind the remaining portion of the blockage may send all or part of the blockage hurtling down the bore in the flowline/equipment until it can be stopped and allowed to melt the rest of the way. Some hydrate blockages may be of sufficient mass that, when they are initially “freed” they can travel at speeds that could pose an issue as it relates to the damage of downstream flowline/equipment hit by the released blockage.
In some cases, the hydrate remediation process may involve bleeding off pressure on the upstream side of the blockage until such time as there is a vacuum (or lower pressure below the hydrate formation pressure) in the bore of the flowline/equipment on the upstream side of the blockage. As the hydrate blockage melts, it sublimates back to its water and natural gas constituents thereby slowly rebuilding the pressure on the upstream side of the blockage. The remediation equipment, e.g., the equipment on the hydrate remediation skid 32, is then used to remove, via the hot-stab 40, the sublimated constituents of the blockage to maintain the lower pressure environment on the upstream side of the blockage such that the melting process continues. However, this continual draw down process has its share of technical problems as fluids/gases are withdrawn and pressure is kept below the hydrate formation pressure.
In general, the hydrate remediation equipment in the hydrate remediation skid 32 is somewhat removed distance wise from the access point 23 in the flowlines 22 and/or the equipment 18, 20 that contains the hydrate blockage. For example, in some applications, the umbilical between 44 between the hot-stab 40 may be about 2-3 meters in length. In practice the umbilical 44 may comprise a plurality of lengths of flexible hose that are coupled together using various connections so as to establish a fluid tight conduit through which liquids may flow. Thus, as the length of the umbilical 44 increases, there are more potential leakages sites in the various hose connections that are used to make-up between the hot stab 40 and the remediation skid 32, which increases the likelihood of putting more mechanical strain on these connections as operations take place, possibly loosening these connections. Examples of potential leakage sources include, but are not limited to, leakage around the remediation skid's 32 internal hardware/plumbing, leakage around the internal seals within its pumping equipment and leakage at the site of the connection to the ROV hot stab access point 40 itself, etc. Specifically identifying when leakages occur and where the leakage sites are located in the overall remediation skid hardware 32 and/or the umbilical 44 in real-time and determining the leakage rate (as well as increases or decreases in the leakage rate) can also be problematic. The location of the pumps, hardware piping and sump hardware in the remediation skid 32 that may be positioned relatively far away from the access point can reduce draw down efficiency and lengthen the duration of the remediation process activities. For example, in the case where production fluid is removed from the flowlines 22 and/or the equipment 18, 20 via the hot-stab 40 so as to create a relatively low pressure on one side of the blockage, leakage in the umbilical 44 can result in water from the surrounding environment entering the umbilical 44 if the hydrostatic pressure is greater than the reduced pressure in the umbilical 44. In addition, since the gauges or sensors that are used to monitor and record conditions during the hydrate remediation activities are located in the remediation skid 32, the readings obtained by these gauges or sensors may not accurately reflect the actual process conditions at or near the hydrate blockage or within the flowlines 22 and/or the equipment 18, 20 because of a variety of factors, such as expansion of the umbilical 44, fluid flow friction losses and the further cooling of the fluid in the umbilical 44 (due to the cold sea water environment) as it travels from the access point 23 to the remediation skid 32, making it difficult to monitor hydrate sublimation.
The present application is directed to a unique ROV hot-stab with at least one integrated sensor and methods of using such an ROV hot-stab that may eliminate or at least minimize some of the problems noted above.